Greetings and welcome to the Antero Resources third quarter 2025 earnings call. At this time, all participants are in a listen-only mode. A question and answer session will follow a formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to your host, Dan Katzenberg, Director of Investor Relations. Thank you. You may begin. Thank you for joining us for Antero's third quarter 2025 investor conference call. We'll spend a few minutes going through the financial and operating highlights and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Mike. Thank you, Dan, and good morning everyone. I'd like to start on slide number three, titled Antero Strategic Initiatives. We are entering an exciting time period for the natural gas market. Rarely have we witnessed such a visible step change in demand. This significant demand growth is driven by increasing US LNG exports combined with a surge in natural gas power generation that is accelerating from the buildout of new data centers. Antero is poised to benefit from these structural demand changes through our long-term vision and recent strategic initiatives, which include adding to our core Marcellus position in West Virginia. We accomplished this through both bolt-on transactions and continuing our organic leasing program to increase our position in the West Virginia Marcellus Fairway. Returning to West Virginia dry gas development to highlight our ability to quickly respond to the regional demand that is beginning to show up in Appalachia. We can either supply directly into future demand projects or grow into the local market if local basis tightens. Also, use hedging as a tool to lock in attractive free cash flow yields to support our dry and lean gas development program and our efforts to be countercyclical in transactions and share repurchases. We believe the execution of these strategic initiatives will enhance our ability to capitalize on the significant demand increases that are expected for natural gas over the long term. Now let's turn to slide number four, which highlights our third quarter operating results. Continuing our trend of improving our drilling and completion results, the third quarter was our most impressive operating performance to date. We set numerous company records and achieved significant progress. The right-hand side of the slide highlights the various company records. We almost 5,000 ft on the completion side, our completion stages per day continues to climb higher, averaging another quarterly record at 14.5 stages per day or 2,900 ft per day. As Patterson-UTI highlighted on their call last week, we set what we believe to be a world record for continuous pumping hours, 15 days of nonstop pumping hours. A truly remarkable feat. Next, let's turn to slide number five, titled Marcellus Core Fairway Expansion. Our additional land investment is driven by the ongoing success we are seeing from our development plan and on the ground from our organic leasing effort. Strong well performance continues to expand our view of where the Marcellus Core boundaries extend. The map on the left of this slide depicts what we believe to be the Marcellus Core at the time of our IPO in 2013. As you can see, we built our position focused on Doddridge and Harrison counties, which we believe will deliver the best drilling results. However, over the past decade, as our development focus shifted into the neighboring counties and our well performance continued to strengthen, these results have driven an increased organic leasing program into those counties. Antero's organic leasing efforts have been a tremendous success over the years. We continue to acquire acreage at attractive levels per location, with the incremental locations more than offsetting our annual turn in lines. Further, this program allows us to maintain our development focus in close proximity to our current footprint, reducing geologic risk while leveraging the benefits of Antero midstream. Now to touch on the current liquids and NGL fundamentals, I'm going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments. Thanks Mike. Several market trends are pointing to improving NGL fundamentals and higher prices in the coming quarters following several years of substantial year-over-year supply increases. Multiple third-party data providers are forecasting a slowing of NGL production growth across the U.S. due to the current low oil price environment and sharp reduction in oil-directed rig counts. Subdued drilling activity in oil basins will have an impact on associated rich gas and NGL production, particularly in the Permian Basin, which accounts for more than half of total U.S. C3+ supply as shown on slide number six, titled U.S. C3+ Supply Growth Slows. The chart on the left shows projected NGL supply growth in the Permian slowing down dramatically in 2026 compared to previous years. At the same time, the chart on the right shows total U.S. C3+ production growth in 2026 is nearly flat, with only 11,000 bbl a day of incremental supply expected. This indicates that while the Permian should continue to rise, albeit at a slower rate, this increase is being offset by even slower growth or outright declines in less economic tier 2 producing regions, including the Bakken, Rockies, and Mid-Continent. The declining expectations for C3+ supply growth comes at a time when exports from the U.S. are now able to ramp up, aided by a debottlenecking of terminal capacity. Year to date, propane exports have increased by over 120,000 bbl a day, averaging 1.85 million bbl a day, compared to 1.72 million bbl a day for the same period last year. This increase occurred despite current global trade uncertainty, illustrating the continued call on U.S. barrels. At the same time, LPG export terminal expansions have started to come online beginning this summer and ample export capacity will be available for the foreseeable future, as shown on slide number seven, titled New Capacity to Ramp Up Exports. Going forward, unconstrained dock capacity will allow U.S. barrels to efficiently clear the market and bring Mont Belvieu prices as close as possible to premium international LPG prices. In the past, Antero has often benefited during times of U.S. Gulf Coast terminal constraints with our ability to export bbl out of market so it can capture high dock premiums. The ability to execute this strategy has served as a differentiator for Antero versus almost all other NGL producers in the U.S. However, it is important to remember that Antero benefits more from higher Mont Belvieu prices than from high dock premiums. This is because higher Mont Belvieu prices lift both our export sales and all of our domestic sales, the latter of which are exclusively priced on a Mont Belvieu index. Antero on average exports less than 45% of its gross C3+ production and sells the remainder of its C3+ volumes in the domestic market. Therefore, an uplift in domestic sales prices is much more impactful for Antero 's NGL realizations. In conclusion, the key challenges of 2025 all trend in our favor moving forward as reduced producer activity combined with higher export capacity and international demand pull is expected to bring propane storage inventories from the top of the 5-year range to near the 5-year average by early 2026. These fundamentals will support Mont Belvieu prices in 2026 and strengthen C3+ prices as a percentage of WTI. With that, I'll now turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market. Thanks, Dave. As we approach winter, we see seasonal and overall positive fundamental demand trends coming for natural gas. I'll start on slide number eight, titled TGP 500L Basis Strength. LNG export demand is expected to increase by 4.5 Bcf from the beginning of 2025 to exit 2025. This increase is almost entirely due to the successful and quick ramp up of the Plaquemines LNG facility. This week the facility achieved a new daily record for feed gas at approximately 3.9 Bcf per day. With the first 18 trains now complete, Venture Global will begin Plaquemines 2, which will increase the capacity by an incremental 2.4 Bcf per day, with the first phase in 2026 followed by the second phase in 2027. The significant demand pull for this LNG facility has led to higher demand along our TGP 500L firm transport path and has driven a higher premium at that delivery point relative to Henry Hub. Looking ahead to the winter, this premium to Henry Hub has increased to nearly $0.80 and in 2026 the premium is now at $0.64 for the full calendar year, the highest level seen to date. As a reminder, approximately 25% of Antero 's gross natural gas is sold at the TGP 500 pricing hub. Our exposure to TGP 500L is expected to lead to higher natural gas realizations. Slide number nine takes a closer look at the significant natural gas demand surge that is coming over the next four months from the new LNG capacity additions. Over this short period, LNG demand is expected to increase by another 10 Bcf per day, driven by the startup of Plaquemines 2, Golden Pass, Corpus Christi 3, and Calcasieu Pass 2. These new LNG facilities are expected to continue to drive higher price premiums along the LNG fairway hubs where we sell 75% of our natural gas. In addition to the substantial LNG demand growth, power demand is also expected to increase significantly over the next five years. The map on slide number 10 illustrates all the competition for natural gas supply in our development region and down our firm transportation corridor. Based on announcements that have been made to date, regional demand is expected to increase by 8 Bcf per day. As Mike has discussed in the past, Antero has 1,000 gross dry gas locations that we could accelerate activity on if there is a regional call for higher supply. Along our firm transportation fairway, there has been more than 3 Bcf of power demand projects announced to date. Additionally, there is an incremental 13 Bcf per day of expected demand between LNG facilities and power projects announced along the LNG Gulf Coast Fairway. All of these projects will be competing for natural gas supply that could face supply challenges in that short timeframe. Antero is uniquely positioned to participate in each of these three regions with our ability to increase dry gas activity for local demand or use our firm transportation portfolio to access increasing demand all the way down to the LNG Fairway. With that, I will turn it over to Brendan Krueger, CFO of Antero Resources. Thanks, Justin. Our capital efficient program that Mike highlighted resulted in attractive free cash flow of over $90 million. During the quarter, year to date, we have generated almost $600 million of free cash flow. Slide 11 highlights the uses of our 2025 free cash flow. Year to date, we have paid down debt by approximately $180 million, purchased $163 million of stock, and invested $242 million in asset acquisitions. We believe this portfolio approach to uses of free cash flow will drive attractive shareholder value creation as we continue to compound this effort going forward. As we've proven historically, we will be disciplined in our transactions. The transactions we completed during the third quarter were accretive to the key metrics that we prioritize, including free cash flow and net asset value per share. Importantly, we were able to fund this activity entirely with our free cash flow in 2025 and therefore did not have to issue equity at today's levels in our financing efforts. Now let's turn to slide 12 to discuss our updated hedge program. During the quarter, we added natural gas swaps for the fourth quarter of 2025 and full years 2026 and 2027. We also restructured our wide natural gas collars for 2026, raising the floor price. As Mike touched on during his comments, these hedges support our strategic initiatives. We have now hedged 24% of our expected natural gas volumes in 2026 with swaps at $3.82 per MMBtu and 28% with wide collars between $3.22 and $5.83 per MMBtu. Our hedge book allows us to protect the downside by locking in a portion of our free cash flow yield. This is illustrated on slide number 13, titled Reduced Cash Flow Volatility. Our hedges have locked in base level free cash flow yields of 6%- 9% at natural gas prices between $2 and $3, while at the same time we maintain significant exposure to rising natural gas prices. Further, these hedges result in a 2026 free cash flow break even at just $1.75 per MCF assuming year to date NGL prices. Looking forward, our return of capital and transaction strategy is anchored by our low absolute debt position that provides us with substantial flexibility to pivot between accretive transactions in our core Marcellus West Virginia footprint, debt reduction and share repurchases. We will continue to evaluate accretive opportunities to increase our net production and core inventory while importantly waiting to increase gross volumes until the broader natural gas market calls for it. While we continue to target maintenance capital, we are well positioned with substantial dry gas inventory for future growth opportunities from the regional demand increases that are expected. With that, I will now turn the call over to the operator for questions. Thank you. Ladies and gentlemen, at this time we will conduct our question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we poll for questions. Your first question comes from Arun Jayaram with JPMorgan. Please state your question. Yeah, good morning gentlemen. I wanted to maybe start with the decision to commence drilling and completion operations on the gas side in Harrison County. I was wanting to know if you could talk about what the catalyst was for that kind of decision. Did data centers, power deals down the road, did that play into the calculus about doing something you hadn't done in 10 years or so? Yeah, that's exactly the catalyst. We've been active in those discussions and it became clear to us all those discussions really related to the eastern portion of our acreage position and where those opportunities would be located, also where the local demand is. We thought looking at our position, we have 100,000 acres, we have significant historical activity there, we have the midstream infrastructure. We have a proof-of-concept pad. It's already a pad that exists with wells going south. If it's drilled north, it'll be very low-cost wells and highly productive and we're excited to get back at it in the Harrison County area. Got it. Maybe my follow-up, just given Mike, this doing a little bit more gas drilling. Thoughts on how you're thinking about a 2026 program at Antero and obviously historically around this time you've decided to do a, call it a drilling partnership, which has defrayed some of the costs. What is your thinking around 2026 at this point? Understanding it's still probably early in the budgeting process. Yeah, it's still early, but we're still at maintenance capital around. This is just one pad, really the fourth quarter production level. We're in the 3.5- 3.525 range. That's the level we'll hold generally in 2026. We're still there. This is just more of a proof-of-concept pad. On the drilling JV, that's still to be determined. We'll see where the market is related to that and we could continue that in 2026, but we haven't made that decision yet. All right, great. I'll turn it back. Your next question comes from John Freeman with Raymond James. Please state your question. Thank you. Just a follow-up on Arun's question with the following. The acquisitions and the higher production level now that you cited that you're going to have in 4Q, just kind of how does that impact the prior commentary about maintenance CapEx? I just think previously you've kind of talked about kind of flattish CapEx to maintain production. Just wondering if this has an impact. This had the same ratio that the increase, you know, the production increased by 3%. It's logical to expect a 3% increase in your maintenance capital. That's like an incremental $20 million from that $675 million level. Got it. Thanks. Looking at the acquisitions, the $260 million of acquisitions in the quarter, just trying to get a better feel for if this is now kind of a bigger focus or was this sort of kind of one off in nature and just you happen to have all these sort of transactions domino during the quarter. Just kind of how to think about that going forward. I don't know if it's a bigger focus. I just think with our position in the West Virginia Marcellus, these type of transactions come to us and are available to us if, you know, it makes sense at the time. When you look at our acreage position, contiguous nature of it, we are the liquids developer in West Virginia and we get opportunities from time to time and we evaluate them and these ones made sense. Thanks, Mike. Yep. Your next question comes from David Deckelbaum with TD Cowen. Please state your question. Thanks for taking my questions, guys. Mike, I guess as we get into 2026, you know, obviously you guys just drilled a record lateral length and we saw the impacts to the average lateral length in the quarter. I guess just given some of the land spends that you have this year, how do you see that progressing on average into 2026 given that you guys have had some pretty significant efficiency gains to date? No, it actually goes up. It's a good, I think it goes up to 14,000. I think we're generally around this year in the low 13,000. Next year's up 1,000. You highlighted the very efficient nature of our leasing program, David. That's exactly what it's doing, is trying to optimize those lateral lengths and also expand our position. Next year's up about 1,000 foot per well. I appreciate that color, Mike. My follow up is just we saw obviously the acquisition this quarter looked like it was an increase in existing working interest, which I guess is. I don't know if you would view that as aberrational or if you view this as a trend that likely continues perhaps into next year. I don't know if we'll have those opportunities. It was three separate transactions, all like with working interest. Another one's royalty interest, another one with more acreage based. Hopefully they continue in the next year. It's hard to forecast. Like I mentioned, we have such a dominant position in this area of the Marcellus. These type of transactions tend to be available to us if they, or if it makes sense and if they're accretive. Appreciate it, guys. Your next question comes from Kevin MacCurdy with Pickering Energy Partners. Please take a question. Hey, good morning. The hedges you added this quarter were unlike past quarters in that you aggressively hedged the next quarter or fourth quarter in this instance and you opted for swaps for next year instead of the wide collars before. Has your strategy on hedging changed or was this just opportunistic? Should we expect you to have a certain hedge level heading forward from here? I think it's probably both. If we could replicate what we have next year where it's these approximate numbers, a quarter with wide collars protecting at $3.25 with exposure up to $6.25 in that high $3- $4 range and then 50% unhedged, that's actually a good model for us. I don't know if that'll be available going forward, but that's a good level for us. When we looked at the program, as Brendan Krueger mentioned in his comments, the ability to lock in above 5% free cash flow yields, I think it's 6%- 9% in the $2- $3 range, but then expose ourselves completely to the upside, up to 20% free cash flow yield, that feels like a prudent way to manage the business. Appreciate the color there. As a follow up, ethane volume significantly outperformed on price and volume this quarter. Was that just due to sales timing or is there any sustainability to that beat? Yeah, Kevin, this is Dave Cannelongo. Really just a function of customers and when they're up and running and taking full volumes. Also, the spreads into the Gulf Coast on ATEX have been improving here in the back half of the year, just taking advantage of our capacity on that system. Great, thank you. Your next question comes from Philip Jungwirth with BMO Capital Markets. Please state your question. Thanks. Good morning. On the dry gas acreage in Harrison County, there's been a lot of operational improvements and advancements in drilling and completion technology since you last drilled here. I was wondering if you could talk to your expectations as to how much of an uplift you'd expect versus kind of the historical type curves from the wells that you had drilled here previously. Yeah, we expect about a 50% improvement. The old wells in that area were more like 1.3 Bcf per day. With today, you know, after 12 years, we've gotten a lot better at it. I think we have approximately 1,500 wells now and those are one of our first. We're excited about optimizing the completion of those wells. It was 1.3 Bcf per day. Expectation is 2 Bcf. I mean 2 Bcf per thousand foot now. Okay, great. I wanted to come back to something you referenced last quarter, with your water systems. I was wondering if you could expand upon the data center cooling opportunity for Antero Resources and Antero Midstream. What would this look like and how would you look to play a role? I think just to build on what we said last quarter, we think we are well positioned and uniquely positioned having that upstream midstream integration. Being fifth largest gas producer in Appalachia, we've invested about $600 million or so in the water system. That provides Appalachia and West Virginia in particular with an advantage. I think relative to other areas, the terrain is a bit more difficult in West Virginia, but we think the advantages of being close to fuel supply, being close to water, having the upstream midstream integration really do position Antero well. Having a lot of discussions, there is nothing to announce at this time, but continue to have quite a bit of discussions there. In terms of as we look at just the regional demand overall, I think we view this as it could take a few different forms. You've got either behind the meter power for data centers. There's been quite a few announcements just on natural gas fired power generation both in West Virginia and the region at large. I think just local prices tightening to the extent you have regional demand and local prices tightening. As Mike had mentioned, we've got that significant dry gas inventory to take advantage of all those various opportunities. The other thing I would just note is, you know, we are intentionally being a bit patient on this as well. I mean, I think as you look at our LNG portfolio, for example, we had many opportunities on Plaquemines, for example, to do long-term deals at certain prices with Plaquemines that were much lower than what we're seeing basis trade at as that LNG facility is ramped up. We do think patience is a bit of a key here. As you let this play out and the scarcity of supply continues to build, we think the ability to do margin-enhancing deals will become greater for Antero. Having a lot of discussions but also taking a patient approach, we want to do the right thing versus just coming out with an announcement just for the sake of coming out with an announcement. Very helpful. Thanks, guys. Your next question comes from Doug Leggate with Wolfe Research. Please state your question. Thanks for having me on, Mike. I wonder if I could pick up on this topic of not, you know, not ceding market share, if you like, in the basin. What's your decision point for growth? I guess I'd kind of frame the question like what are the conditions you need to see? Do you need to see basis improve or is it just about local demand increasing before you decide to step into dry gas growth in your backyard? Yeah, Doug, interesting question. We've been talking about that. Obviously, this is a proof-of-concept, so we'll see the results on this. We're highly encouraged currently. You mentioned ceding the basin. We are the dominant producer in West Virginia. I think we produce over 40% of the state's natural gas. We have the dominant acreage position, we have the midstream, we have the acreage HPT, we have investment-grade balance sheet, I mean everything you'd want for developing it. Why shouldn't we develop it? It's proof-of-concept. We'll prove out the resource and then when you look, local demand absolutely would encourage us to grow into that. Also, if you kind of look out the curve, if you get, you know, $4 NYMEX natural gas and you could hedge basis in the future years, that may be something we would entertain as well. A lot of kind of different decision points there, but like I said, we're uniquely positioned for this one. We're very encouraged and we look forward to this paddle. I appreciate that. Of course, given the depth of the inventory you have, you've got a lot of optionality. It does raise the question, and you got to forgive me for this one, about the rest of your portfolio and the potential for asset sales and you know where I'm going with this. In Ohio, can you offer any color, confirmatory or otherwise, as to where you are in that process? Yeah, we're just in the middle of that process, Doug. We're highly encouraged there as well, as you can imagine. I mean, that's a highly desirable or coveted asset with the contiguous acreage position, all the midstreams in place, the ability to access the firm transport, to price it outside of the basin, the liquids portion, the dry gas portion, you know, it's kind of ready-made asset for companies. Also, all the data centers over in Ohio as well and all the power demand over there. It's highly coveted. That's kind of why we wanted to do a market check. We're just in the middle of it, but we are encouraged. Great. Thanks so much, guys. Your next question comes from Betty Jiang with Barclays. Please state your question. Good morning. I want to go back to the data center proof-of-concept. It seems to me that you don't need to prove to the market that you can grow dry gas and grow it very cost effectively. This proof-of-concept is really for the customers and people you're speaking to on the other hand. My question is that these customers and entities, what are they looking to derisk with your proof-of-concept pad? Is it the speed at which you can deliver volume? Is it the capacity of resources that you can deliver to? Once that pad is online, could that catalyze the conversation that you're having on the power and data center side? I think the proof-of-concept is twofold for us, and then I'll let Brendan talk about his discussions with the counterparties. For us, it's one, what's the EURs? What's the deliverability? Just so we know, we haven't drilled a well over here in 12 years. Is it the 2 BCF, is it higher than that, is it lower? We'll see. How to optimize that development, but also in the midstream, a lot of midstream capacity over there, showing that we can flow it into these local kind of sites where these data centers are potentially being located. Just the ease of our ability to deliver gas straight to the actual facility. I'll let Brendan talk about other customers. Yeah, I think just to add on top of that, I think from the standpoint, we haven't drilled a well over here in 10 years. It just shows we've got the inventory over here. It'll give them good perspective on the ability to quickly ramp up. I think having the ability to have that residue gas not only at the processing facilities in the western part of our play, but also on the eastern part of the play where you're seeing some announcements out there on gas-fired generation, it provides just more flexibility in discussions. Like as I mentioned, we're having multiple discussions and the ability to have flexibility around these discussions and what could be best for Antero as it relates to kind of margin enhancement. This just gives us more flexibility, having different parts of the play producing in larger ways. Got it. That's helpful. My follow-up is on the land budget. You have increased it for 2025, but I'm wondering if the land budget would just be higher for longer given you have expanded the scope or the boundaries of what you define as core. Can you just speak to the attractiveness of the organic leasing initiative versus potentially what you see in a private space in that area? Yeah, we generally go, so our kind of base organic leasing is always kind of looking out the next 24 months and trying to enhance those, the working interests or the lateral lengths like we discussed earlier. That's generally up to the $75 million, you know, $50 million- $75 million level. Above that is the expansion and what do we see in a particular year. We go into generally in the year in that $75 million- $100 million range, and that's where we've been the last three years. This year we've just seen a lot of opportunities because our wells continue to strengthen in these areas that we're developing, and there's more acreage in those areas than there have been kind of in the middle of the field. Our opportunity set continues to grow as our wells and our continue to support that. Right now it'd probably go into next year and I think most people's models have about $100 million, but if we continue to see opportunities throughout next year that could be higher, kind of in the back half of 2026 if this level of activity continues. Got it. Okay, thank you. Your next question comes from Jacob Roberts with TPH. Please state your question. Good morning. Good morning. I wanted to ask about cash taxes. I think on the last update you gave the market, it was a 2028 time frame. Those commodity prices. Just wondering if that math has changed at all given where we sit today. No, no change there. No material cash taxes through 2027-2028 would be that first year we expect to pay some. Okay, perfect. And then circling back to the dry gas activity. This six well pad or the activity going on currently to get to that 50% uplift relative to a decade ago. Should we be expecting some iterative completion design or is this ready to go into manufacturing mode? Ready to go. I mean, like I mentioned, I think we've since that time drilled over a thousand wells. It was primitive back in 2013 when you look at it. It would just be doing our typical, you know, 36 bbl of water per foot, 200 foot stages. The spacing on it, is it like 830 foot spacing? Lateral between the laterals. Just our typical design in the liquids, but just applying it to the dry gas for the first time in 12 years. Great. Appreciate the time. Sure. Your next question comes from Nitin Kumar with Mizuho Securities. Please state your question. Hey guys. Good morning and thanks for taking my questions. I want to start on the hedging you addressed earlier. It's a little bit more prudent sort of financial management. I agree. As you've kind of put a floor on your free cash flow yield, what are your thoughts on the cash return profile? You know, you've kind of not done a dividend like some of your peers as you're stabilizing your cash flow. Is that part of the discussion going forward? I don't think a dividend, but I think we can be very countercyclical on share repurchases with locking that in, also evaluating transactions even in a low commodity price environment. We always want to be countercyclical and we have really no debt, very low debt, no maturities for years and years. We want to be countercyclical. If you don't have the hedges in place when the counter cyclicality happens in low commodity prices, the free cash flow is not there as well. We wanted to lock in a baseline of free cash flow and then be able to use it for share repurchases or transactions is where we're thinking. Great, great, I appreciate that. The topic of M&A has been covered quite a bit, but you confirmed earlier that you're marketing the Ohio assets. Just curious, as you mentioned, you don't have a lot of near term debt or a big balance sheet. What do you think would be the use of proceeds if you were successful in getting the price you want? Yeah, it's a good question and that's why it's a high bar for us because, you know, the most likely case, I would still say it's the hold case, but we'll see where the marketing goes. The use of proceeds right now is like you mentioned, we're at $1.3 billion of debt. We have $300 million on our credit facility. Then we have, I think, $400 million on a 2029 that's kind of callable, at par. We really only have $700 million of prepayable debt. There's $600 million, so 2030 maturity, I think 5 and 3/8. That's a good piece of paper. You also look at where our equity trades and the type of valuations that you're going to see for the Utica as well in excess of where equity trades. That could be a use of proceeds as well. It wouldn't be a bad trade if you sell your Utica for well in excess of where your equity trades and use that to buy into shares. Appreciate it. Good luck. Sure. Your next question comes from Leo Mariani with ROTH and MKM. Please state your question. Yeah, hi. I just wanted to follow up a bit more on this concept of growing net volumes without growing, you know, sort of gross, you know, in the near term. Obviously you talked about M&A. Sounds like you're undecided on the drilling partnership here, but just in terms of the M&A strategy. Other than undeveloped acreage, are there opportunities to continue to pick up minerals, working interest? Are you generally trying to do this kind of ahead of the drill bit over the next kind of 12 to 24 months? You said that these three deals kind of came up recently. Are you seeing just kind of more deals in the basin? Just want to get a little bit more color around some specifics on the M&A strategy here and kind of growing the net without growing the gross. Yeah, I think you hit on it. These are all small bolt-on transactions, increasing interest. When we talk about gross versus net, all of our processing is full. I think we're at 106% of processing capacity. All the FT's full. On the liquid side, it's a challenge to grow gross because all the facilities are full. In order to grow that you have to look to the working interest and the royalty. All of these are highly free cash flow accretive. That's where our head's at. As they come up, we assess them and see if it makes sense based on that. Like we've been talking about a lot on this call, the ability to grow the dry gas, it's really on regional demand and local basis. That is an opportunity for growth there. Really just trying to grow the net and maintain the gross volumes. Okay, that's helpful. You obviously highlighted a number of kind of operational records on the quarter with just some very strong improvements in terms of frac stages and cycle times and everything. Can you just give us any thoughts on whether or not you think there's a decent amount, kind of more improvement to come here, or do you think you're starting to kind of maybe bump up on some of the limits? I guess 15 days in a row without stopping on the frac side seems like maybe hard to do a lot better than that. Yeah, if we continue that. When you get those days, you're doing 16, 17, 18 stages a day. We averaged 14.5 during the quarter, so we get more continuous pumping throughout, which is our goal. I think you could see that go a bit higher. Right now I think if we had a pad and had this type of performance, you'd think it'd be averaging on the 15 stages kind of per day. A little bit of improvement. The 14.5 stages is really high. Okay, thank you. Thanks, Dan. Your next question comes from Kalei Akamine with Bank of America. Please state your question. Hey, good morning, guys. Maybe to start, I'd like you to talk to slide number five and the one that illustrates the expansion of what you consider to be core in the Marcellus. Activity in the east in areas like Wetzel and Tyler, that's been robust for quite a while and it's easy to see how that is now core. Activity to the south and the east has been a little bit less frequent. What gives you confidence that the core is expanding to those areas? Our recent well performance is, you know, we, Tyler and Wetzel, but it's also been in the kind of in the eastern portion of Richey and northern part of Gilmore and you look at some other competitors and they've had good results down in the Gilmer Lewis area. You see, seen that. Like we talked about on the dry gas that's in Harrison County. I appreciate that for my second. Got it, Mike. I appreciate that for the second question. I'll go slide number 10 here. Gas demand is expanded across that pipeline fairway. Two questions. Pipes in that direction are quite full. Do you guys have visibility on maybe new FT opportunities to push more gas into that region? It feels like given the demand pull, there's increased competition in the Gulf to lock these volumes down. Do you see any direct to consumer opportunities along this route that you could participate in? I think, Justin, correct me, I think we had 2.1 Bcf a day going down into the Gulf. Yes. We've intentionally been floating like Brendan's comments suggested. We've carried this for quite some time. We're going to see where the actual basis goes. When you look at these type of opportunities in demand growth, 25 Bcf a day, 17 Bcf of it being in the Gulf Coast or along that path, we think there'll be a lot of opportunities. I can let Justin expand on that. Good morning, this is Justin Fowler. The way we think about this, on Mike and Brendan's previous comments, the local demand, if all these projects go forward, it's going to be there. That's going to drain gas out of various local pipes, various local pools. To Mike's point, when you think about the Antero 2.1 or so Bcf of southbound, there was approximately 10 Bcf reversed over the years since the shale revolution took off. Right there we're about 20% of that volume heading south. When you really zoom in on some of our pipelines, which we're calling Midpath, Antero owns rights past those potential projects as well. We are evaluating different projects in Kentucky, Tennessee, Mississippi, where we cross. To your point, on just the LNG market, the LNG groups are going to have to potentially start to lock in supply just as there will be scarcity across the summer season, winter season, et cetera, that could cause peak situations. We have been talking to a lot of those groups as well. To Brendan's point, patience is key at the moment and there's a lot still to be developed. If I understood your first part of your question correctly, in terms of new capacity being added southbound, it's just such high cost and any of those projects are going to be toward the end of the decade. Antero is in a good situation here to continue to watch the basis locally and just that behavior locally and then also just working with these various groups in the midpath delivery points if those projects move forward. The only thing I would add just on the point about end users, there has seemed to be a bit of a shift in terms of the demand pull side of things. When the Basin took off, it was more of a producer push. There has been a lot more significant interest from a demand pull perspective and folks wanting to get the actual supply due to some of that scarcity of supply that I think is starting to take hold in the market now. Sounds like a good opportunity set. Thanks guys. Thank you. Thanks. Your next question comes from Neil Mehta with Goldman Sachs. Please take your question. Yeah, good morning team and Mike, congratulations on stepping into the CEO role. I just love your perspective early on. It's been a couple months now of just observations as you step into this new role and the business has done very well over the last couple of years, particularly coming out of COVID. What do you think the next frontiers are from a strategy perspective as you look to the next end of this decade? Yeah, I think you saw that in the strategic initiatives, Neil. We have such a terrific asset and, you know, best rock, some of the best rock in North America, definitely the best rock for liquids development, in midstream access, midstream capacity, balance sheet, investment grade. It kind of ticks all the boxes. The strategic initiatives going forward are just trying to enhance that, doing bolt-on acquisitions in West Virginia, trying to enhance our exposure there, some dry gas development like we've talked about, that's a good opportunity for us. Using hedging as a tool, that's one thing that, like I mentioned, we want to be countercyclical. One way to do that is perhaps have some sort of certainty of cash flow during low commodity price times. That's kind of the next frontier that we're looking at. We're excited about it and, like I mentioned, we are at the dominant position in West Virginia. We should expand upon that. Very clear, Mike. I just wanted to go to the macro on NGLs and, as we watch your pricing sheet, it's a tougher environment right now. I guess it's not so bad when you look at as much percentage of WTI, but on an absolute basis it's pretty challenging. Just talk about the path for recovery in 2016. Do you think that recovery is going to be more supply driven or demand driven? On the supply side, I saw you put out some interesting numbers in terms of volume growth. It's probably below where I think consensus is for volume, volume growth in the Permian for NGLs next year. Is that an out of consensus view that you guys have that we can offset sort of the prevailing view that even if black oil is flat, NGLs will still be growing significantly? Yeah. Neil, this is Dave Cannelongo. I'll take that one. To your first question on looking forward to 2026, oil prices do play a key role in what happens with NGL pricing. As you alluded to as a percentage of WTI, it's been improving here in 2025 despite some of the market headwinds that were out there. If you look back at 2024 through the first nine months of the year, a little less than 54% of WTI, 60% of WTI here in 2025. That really speaks to the value for NGLs is still there, driven by Rescom, inelasticity and F chem demand. Looking forward to 2026, we're very optimistic about the trade uncertainty getting resolved here. Some announcements this morning we think will certainly thaw some of that. If you look back to what was being exported in particular to China prior to the tariff announcements in early April, it was around 600,000 bbl a day or 1/3 of U.S. LPG exports headed that direction of propane exports. In June it was a little less than 100,000 bbl a day and since rebounded to about 300,000. Certainly some thawing there, but we'd like to see that continue to improve. That will help with efficiencies on freight pricing, which will also drive Mont Belvieu higher. Those are the key things we're looking to. I don't know how long the world can sustain at a $50-something per barrel WTI as well. You expect at some point that's going to resolve itself. It also becomes a tailwind for NGL prices on an absolute basis. Coming back to the supply picture and your questions on that, that view is a third-party view that we've put in our presentation. There are a lot of different groups that are out there. There's been some consolidation in the third-party analytical groups, so there aren't as many people out there providing views. It seems to be a belief around gas oil ratios increasing and that really seems to be what's behind some of the higher NGL supply growth views. Undoubtedly, I don't think anybody's disputing in this oil price environment and lower rig count environment that NGL supply growth is going to be as strong as it was if you're looking at the chart in the prior years. Thanks team. Appreciate it. Your next question comes from Paul Diamond with Citi. Please state your question. Thank you. Good morning all. Thanks for taking the call. Just wanted to touch quickly on kind of capital allocation given current conditions. You know, with your hedge book, you guys put on a pretty decent $400 million free cash flow next year and have used evenly between stock repurchases, debt repayment, and acquisitions. I guess in kind of a bull scenario, how much cash would you be willing to build if you want to really maintain countercyclicality, assuming that you have limited debt to really buy back now and if your stock starts to run, what level of cash is comfortable? Yeah, that'll be a good problem to have. I think I mentioned earlier we have $700 million of debt that we can pay down. Of course, we'd be buying shares all along that way as well. In a real bull case scenario where you get into a couple billion of free cash flow a year, you would start to build some cash. I think, unless you didn't really have any other transaction opportunities, you'd kind of be where we're at right now where it's kind of like a third repay of debt, a third equity purchases, and a third in transactions. Got it. Just kind of switching to the other side of that coin. Some of your peers have really started to do production management, whether it's curtailments or choking or anything along those lines. Given your FT, I know it's less of an opportunity for you, but just wanted to see if you saw how Antero would play in that on the margins. Is that something you haven't looked into or— When we do it, we just don't talk about it. It's already built into our guidance and it's really kind of—they may say it's curtailment practices, but I think it's really economics based. The gas prices are low in the basin so it wouldn't make economic sense to flow to that whenever that occurs, which is rare. Like you mentioned, with the FT and the liquids, we don't really have that much local basis exposure, but we do have it from time to time. We always build that in the risking of our guidance. Got it? Understood. Appreciate the clarity. I'll leave it there. Thank you. Ladies and gentlemen, there are no further questions at this time. I'll turn the floor back to Dan Katzenberg for closing remarks. Thank you. Thank you. Thanks everyone for joining the call today. Please feel free to reach out with any questions that you have. Have a good day. This concludes today's call. All parties may disconnect. Have a good day.